1. Field of the Invention
The present invention relates to systems and methods for production of petrochemicals including those for stimulating the production of petroleum from a well. The invention also relates to systems and methods for enhanced production of petrochemicals from single or multiple subterranean zones, or single or multiple sections of such zones, in various completions, including horizontal completions. The invention also relates generally to a well control valve, specifically, a flapper valve having a specially-shaped flapper being used as a mechanically-operated well control valve that is a vital part of a single-trip well completion system used to improve productivity and enhance control of the well.
2. Description of the Related Art
During a typical production operation of a multizone completion, a production string is introduced into a cased wellbore which has been previously perforated and the string is then placed so that production ported nipples are positioned proximate the perforations. Packers are then set between the production string and the wellbore casing so as to isolate the production ported nipples and perforated sections into production zones. During a well's completion, production must often be stimulated by injection of acid or other chemicals into the perforations. To accomplish this, a stimulation tool is introduced into the production string and positioned so that acid flow ports are aligned with the production ported nipples.
Present systems and methods for completion and stimulation of production zones have certain disadvantages. For instance, because the stimulation tool is introduced separately from the production string, it is difficult for operators to properly locate the acid flow ports in relation to the production ported nipples, which can cause the acid to be misplaced. Separate running of the stimulation tool for each zone to be treated results in extended rig times, which significantly increases cost.
Problems can also occur when a stimulation tool or other tool is being removed from the wellbore. As the stimulation tool is removed from the wellbore, fluids are swabbed out of the well in the process, causing the well to become unstable. In horizontal production arrangements, formation pressure may vary significantly at the same depth or for relatively small changes in true vertical depth. Thus, some zones to be completed may have greater pressure than the hydrostatic head while other zones may be at lower pressures than the hydrostatic head. The effect of these pressure conditions is that some of the zones in the horizontal well will tend to take on fluids while others will tend to flow, resulting in what is termed an underbalanced situation. Present solutions to these problems, including increasing mud weight, can be time consuming and may damage formations, adversely affecting potential recovery of hydrocarbons.
Existing devices used to address swabbing and/or control of underbalanced situations include foot valves and closing sleeves. Foot valves are mechanically operated flowbore valves which are controlled through tubing manipulation by a well operator. The foot valve is most often a valve which closes the wellbore as an operator removes a "stinger" or other tubular member from the valve assembly. The foot valve is reopened by means of a stinger which is inserted into the valve assembly to mechanically open the valve.
Foot valves are distinct in operation and employment from other wellbore valves such as safety (or "fail safe") valves and other surface controlled valves. Safety valves are normally closed valves and are designed to close automatically in response to one or more sensed well conditions, such as those indicative of an emergency. Although "surface controlled" valves may be closed at will, rather than automatically, they require some sort of auxiliary control means to operate. Surface controlled valves are opened and closed either by electrical control or by means of hydraulic pressure actuation. Although valuable, surface controlled valves are vulnerable to interruptions in their control means. Because of the difference in function, foot valves are typically employed much deeper within a wellbore than a safety valve. A safety valve is normally employed in depths above 2,000 feet in order to close off the well in case of an emergency. A foot valve, however, is usually required deeper in the wellbore (5000-20,000 feet) and in the vicinity of the lower most production packer.
One example of a foot valve is the Otis 212FO Back-Pressure Valve (PC/5063) which was marketed by the Otis Engineering Corp. in the late 1960's. The Back-Pressure Valve, attached to the bottom of a packer, was designed to shut off flow from below the packer when the sealing unit and tail pipe were removed. The valve featured a pivotable flapper-type plate which sealed against a resilient seal and metal seat.
Ball-type foot valves are also known. The Otis "PERMA-TRIEVE".RTM. Packer with Foot Valve, for example, employs a ball-type valve which is connected to the bottom of a packer and opened and closed by a stinger run on tubing with an Otis Seal Unit. After the packer is set, the seal unit with stinger attached opens the foot valve as it enters the packer bore. When the seal unit is retrieved, the stinger is designed to close the valve as it is removed.
It may be desirable to perform work in a wellbore at a depth below where the foot valve have been installed. Due to the size (outside diameter) and configuration of the tools to be inserted, and the internal restrictions of the prior art valves, it can be difficult, if not impossible, to perform the desired work below such valves without removing them. The prior art valves described above are difficult to conveniently fit into the wellbore while maintaining the full bore of the production string's inside diameter. Due to their size and shapes, such valves tend to present obstacles to inserted tools, particularly those with radially extending profiles. Surface irregularities of inserted tools, such as extending keys, could prevent passage of the tools through the valve, prematurely activate the valve or damage the valve. Prior art foot valves having flat flappers do not provide sufficient outside diameter (OD) to inside diameter (ID) ratios to allow full bore tool passage in a restricted casing. For example, the flapper plate of the Otis 212FO Back-Pressure Valve (PC/5063) presents a flat upper face when the valve is in a closed position. When the valve is opened, the flat face will restrict available flowbore space, necessitating a reduction in the size of tools which can be run past the valve. These space limitations dictate against use of a flat plate flapper valve in a well control valve application.
Accordingly, there is a need to improve the economics of well completion by reducing rig time. Toward this end, it is highly advantageous to isolate zones and selectively stimulate the zones of a multiple zone well in a single trip.
There is also a need to provide a stimulation system that provides a positive indication of the position of stimulation tools in the well during stimulation.
There is also need to control the flow of fluids into and out of each of the zones of a multiple zone well, a further need to maintain hydrostatic balance during completion, and a further need to prevent swabbing which may occur upon removal of the stimulation tools from the wellbore.
There is still a further need to provide a well control valve that can be used in a single trip completion system that allows for passage of an inner string through said well control valve while maximizing the outer diameter of the inner string.
Additionally, there is a need to provide a well control valve which prevents flow from the production zones once stimulation of all production zones is completed.
The present invention overcomes the deficiencies of the prior art.